NO20140627A1 - IDENTIFY CANCER IN A DRILL - Google Patents

Abstract

A downlink telemetry system which provides an improved device and method for communicating instructions via pressure pulses from surface equipment to a downhole unit. The device comprises a surface transmitter (6) for generating pressure pulses, a control system and a down-hole receiver for receiving and decoding pulses. In operation, a bypass valve (10) is opened and closed to generate a series of pressure pulses received and decoded by a down-hole receiver. The method significantly reduces the time required for downlink communication without interrupting drilling and without interfering with uplink communication, so that simultaneous bidirectional communication can be obtained if uplink and downlink signals are transmitted at different frequencies. The telemetry scheme and algorithm provide an invented method for filtering and decoding the downlink signals. The algorithm determines the time intervals between pulse peaks and decodes the intervals of an instruction. The algorithm also includes error checking to verify that the instruction was correctly received downhole.

Description

Field of the invention

The present invention relates to systems and methods for identifying forces on an element that is moved inside a borehole, and in particular for identifying such forces from surface measurements measured by a rig to which the element is attached. The present invention is particularly suitable for use when the element is a tubular element, for example a casing string, casing string or a pipe string such as a drill string, injection pipe string or a production pipe string.

Background

During and after the drilling of a borehole, tubular elements are lowered into or raised out of the borehole. In an example case, the tubular element is a casing string, which is usually a tubular steel pipe that serves to line the borehole, and therefore to isolate rock formations surrounding the borehole from fluids passing along the borehole. The process of lowering the casing string into a borehole is usually called running the casing string.

A string of casing (or other tubular element inside a wellbore) generally consists of several sections or "legs" of a standardized length, typically 12 meters (40 feet). The process of moving the casing string therefore continues in a series of repeated cycles, where each cycle involves adding or removing a link to/from the upper end of the existing casing string and then moving the casing string inside the borehole so that the process can be repeated. This process will be described in more detail below as part of an embodiment with reference to Figures 2a to 2d.

While the casing string is being moved, it is attached to a movable device, typically called a "hook". The hook can be raised and lowered by a rig to move the casing string inside the borehole. The hook, or the equipment attached to it, is capable of measuring the "hook load", which is the total force on the hook. This force depends on the weight of the casing string (including couplings and other auxiliary equipment), as well as any forces on the casing string caused by friction between the casing string and the borehole wall, for example, buoyancy on the casing string caused by the immersion in fluids, viscous resistance caused by displaced fluid and any pressure in the borehole which acts on the cross-sectional area of the casing string.

Traditionally, the hook load is measured to track the progress of the run-in of the casing string. One measurement of the hook load is taken for each lowering cycle. This measurement is typically a steady-state measurement performed "by eye"; that is, a human operator on the rig looks for a steady state in the hook load during the lowering of the casing string and records this as the hook load for that cycle. Since the operator is looking for a steady state during the lowering of the casing string, this measure of hook load can be used to calculate a measure of the dynamic friction (also known as kinetic friction) present between the casing string and the wellbore. The measured hook load value may be known in the art as tripping-in weight.

A casing string (or other tubular element), which is moved inside a borehole, can become stuck so that it cannot be moved any further (either rotated or moved axially, up or down). Such situations, commonly known as "stuck casing" or "stuck pipe", are generally caused by excessive static friction along the borehole. One particular cause of a "stuck pipe" is "differential jamming", which is a situation where a tubular member is pressed against the side of a borehole so that it contacts the side of the borehole along a substantial length of the tubular member; however, other causes of a stuck pipe are borehole collapse or some form of borehole instability.

A stuck pipe is one of the biggest problems associated with drilling a well and can result in many days of lost productivity, result in the loss of equipment (because the casing string or other tubular elements cannot be salvaged), and can reduce production to a resulting well (due to narrower drill pipe having to be driven down into the stuck pipe).

As is known, static friction is the measure of friction between two surfaces that are stationary in relation to each other. In contrast, dynamic friction is a measure of the friction between two surfaces moving relative to each other. The causes of static and dynamic friction inside a borehole are different, and consequently the magnitudes of the frictional forces are different in each case, with static friction generally being greater.

Therefore, it has been found that the measures of hook load, and therefore the measures of dynamic friction as described above, are unable to identify the magnitude or type of static friction in a borehole.

It is an object of the embodiments to identify the magnitude and type of friction between the borehole and a tubular element within it, and consequently to enable a more effective prediction of a stuck tubular element (stuck pipe) as well as to facilitate diagnosing conditions in the borehole which can lead to a jammed tubular element.

A further problem that can occur when moving an element in a borehole, either to drive in or withdraw the element, is that the element's movement causes a downhole pressure wave. This pressure wave can cause damage to the formation and can cause the fluid to leak out of or be drawn into the formation. It is therefore a further purpose according to embodiments to enable the effects of the fluid's movement downhole to be detected.

Brief description of the invention

According to at least one embodiment, methods, devices, systems and software are provided to support or implement functionality to provide identification of a spatial relationship between a first and a second frame of reference, as specified in the independent claims. This is achieved by a combination of features listed in each independent claim. Consequently, independent requirements set out further detailed implementations.

According to a first aspect, a system for identifying a force on an element being moved within a borehole is provided by a rig, the rig comprising a movable unit to which the element is attached to be moved within the borehole, and wedges to hold the element, wherein the element is moved in a plurality of cycles, each cycle comprising, in sequence, holding the element in the wedges, releasing the wedges so that the element moves within the borehole, and applying the wedges so that the element is again held by the wedges, and the rig comprises a measuring unit arranged to measure a force transmitted by the element of the movable unit, and being arranged to output first data indicative of a plurality of load values, each data element of the first data being indicative of the force measured at each of a plurality of points during the cycle , where the system comprises: an interface arranged to receive data from the measurement unit; and a data processing system arranged, for each of a plurality of the cycles to: identify a plurality of load values from the received data, each load value corresponding to a different time with respect to the cycle, and determine other data indicative of the friction between the borehole and the element from the identified the plurality of load values.

The element moved within the borehole may be a tubular element, for example a casing string, a casing string, a pipe string such as a production pipe or injection pipe or a drill string. When the tubular member is a casing string, the borehole may be an open hole. When the tubular element is, for example, an injection pipe string or a production pipe string, the borehole may have been lined with a casing string or another form of casing string already.

The average hook load during a cycle is typically the combination of the weight of the member and dynamic friction between the member and the borehole. Consequently, average hook load by itself does not give any indication of the other forces on the element, such as static friction between the element and the borehole that is present before the element begins to move within the borehole and viscous resistance forces caused by the displacement of fluids in the wellbore. Therefore, by identifying a given cycle's plurality of load values, and by determining the other data indicative of a force from the identified plurality of load values (ie, those during a given cycle), the system is able to identify the force on the member by to look at the variations in, and the development of, load values over the cycle.

The data processing system may be arranged to identify a monotonic change in the plurality of values over the cycle, and to determine a magnitude of the monotonic change to determine the other data. The data processing system may be arranged to identify a linear trend in the plurality of values, and to determine a difference between a value of the trend at the beginning of the cycle and a value of the trend at the end of the cycle to determine the other data. In some embodiments, the data processing system may be arranged to identify a linear trend in the plurality of values and to determine a gradient of the trend to determine the other data. In these cases, the other data may be indicative of a viscous resisting force on the element as it is moved within the borehole.

Viscous resistance forces are caused by the displacement of fluid in the well. The displaced fluid opposes any movement of the element, thus varying the force on the movable unit. Viscous resistance forces tend to build up during a given cycle, and therefore a measurement of the viscous resistance can be made by looking at the variation in the load value during a given cycle, particularly by looking for a monotonic change in the value. From this measurement, the probability that, for example, fracturing in the borehole caused by the fluid movement can be established, and the movement of the element can be adjusted accordingly (ie reduce or increase the speed of movement).

In some embodiments, the data processing system is arranged to: determine the other data of a plurality of the cycles; and determining, using the other data, whether friction between the borehole and the element is increasing. Alternatively or additionally, the data processing system may be arranged to determine a trend in the other data to determine if friction between the borehole and the member is increasing. In some embodiments, the data processing system may be arranged to calculate a risk value indicative of the probability that the element will become stuck in the borehole, based on the other data.

One cycle may provide an erroneous result, or likewise, static friction may be high during one cycle, but having been overcome, the cause is removed and the static friction does not occur again. In order to provide accurate results, it is therefore advantageous that several cycles can be compared to detect trends in the data. These

the tendencies can be used to identify a precipitating cause of static friction and therefore a high risk of the element getting stuck.

The data processing system may be arranged to determine a variation of the plurality of load values to determine the other data. Alternatively, the data processing system may be arranged to compare the plurality of load values with a predicted load value to determine the other data. Alternatively, the data processing system may be arranged to identify an average value from the plurality of load values and a minimum value from the plurality of load values, and to compare the average value and the minimum value to determine the other data. Thus, the data processing system may be arranged to calculate at least one of a mean value, a weighted mean value, a frequency class, a median value, or a steady state value to determine the mean value.

The system can identify friction in a number of ways. In general, this is done by looking at the variation in the load values, a high variation, and especially a low output value followed by a sharp rise during the cycle is an indication that static friction is being overcome. The difference between a low value (when static friction supports the casing string) and an average load value can be used to derive a measure of the static friction. However, alternatives are possible, such as looking at the magnitude of oscillations in the load value.

In some embodiments, the data processing system is arranged to: identify a time period in the load cycle, where the period is between the wedges being released and the wedges being applied; and identifying a set of the load values corresponding to times during the identified time period to identify the plurality of the load values. Alternatively, the data processing system is arranged to detect a change in the load value between a level indicative of the element being held in the wedges, and a level indicative of the element being supported by the movable unit, to identify the time period.

It is advantageously correct to identify the period in which the load values are actually representative of the weight and friction of the movable unit. Therefore, errors associated with the transfer of the load from the movable unit to the wedges and vice versa can be avoided by identifying the period described above.

The data processing system may be arranged to compare the load values with a threshold value to detect the change. The data processing system may be arranged to identify the time period to start a predetermined duration after a detected change. The data processing system may be arranged to identify the time period to end a predetermined duration before a detected change.

The data processing system may be arranged to detect at least one oscillation in the load values associated with the wedges being released or applied to identify the time period.

The data processing system may be arranged to receive positional data indicative of the movable unit's position at the given times; and wherein the data processing system is arranged to determine the position of the movable device by using the position data to identify the time period in this manner. The data processing system may be arranged to determine whether the movable device is between a first and a second position to identify the time period in this manner. The data processing system may be arranged to determine whether the movable device is in motion to identify the time period in this manner.

The data processing system may be arranged to receive operation mode data indicative of whether the wedges are applied or released, and wherein the data processing system is arranged to use the operation mode data to identify the time period.

While load values in themselves can be used to identify the period described above, it is possible to use data from other sources to ensure an accurate detection of the period. For example, the movable assembly will move between a first point (where the movable assembly is attached to the member and the wedges are first released) and a second point (where the wedges are reapplied and the movable assembly is not attached to the member). If the movable unit is between these two points, then it is likely that the lowering cycle period is to be identified. Accordingly, the position data indicates whether the element is moving. Alternatively, the system may check whether the movable device is in motion from the position data to detect this period. Similarly, the wedges are applied at the beginning and end of a cycle; therefore, if the wedges have been released, then it is likely that the element is attached to, and dislodged from, the removable assembly.

According to a further aspect, there is provided a method of identifying friction between a borehole and an element within the borehole, wherein the rig comprises a movable unit to which the element is attached to be moved within the borehole, and wedges to hold the element,

wherein the element is moved in a plurality of cycles, each cycle comprising holding the element in the wedges, releasing the wedges so that the elements move within the borehole, and applying the wedges so that the element is again held by the wedges, and the rig includes a measuring unit arranged to measure the force transmitted by the element on the movable unit, and which is arranged to output first data indicating a plurality of load values, each data element of the first data indicating the force measured at each of a plurality of points during the cycle, the method comprising: receiving data from the unit of measurement; and for each of a plurality of the cycles: identifying a plurality of the load values from the received data, each load value corresponding to a different time with respect to the cycle, and determining other data indicative of the friction between the borehole and the element from the identified plurality of load values.

According to yet another aspect, a computer-readable storage medium storing computer-readable instructions thereon is provided for execution on a computer system for implementing a method of identifying friction between a wellbore and an element within the wellbore, the rig comprising a movable unit to which the element is attached to be moved within the borehole, and springs to hold the element, wherein the element is moved in a plurality of cycles, each cycle comprising holding the element in the wedges, releasing the wedges so that the element is moved within the borehole, and applying the wedges so that the element again held by the wedges, and the rig comprises a measuring unit arranged to measure a force transmitted by the element on a movable unit, and arranged to output first data indicative of a plurality of load values, where each data element of the first data is indicative of a force measured at each of a plurality of points during a cycle, the method comprising: receiving d ata from the unit of measurement; and for each of a plurality of the cycles: identifying a plurality of the load values from the received data, each load value corresponding to a different time in relation to the cycle, and determining the other data indicative of the friction between the borehole and element from the identified plurality load values.

Further features and advantages will be apparent from the following description of preferred embodiments, for example with reference to the accompanying drawings.

Brief description of the drawings

A drilling rig system will now be described as an embodiment, by way of example only, with reference to the accompanying figures in which: Figure la shows a schematic diagram of a drilling rig system comprising a drilling rig and rock formations being drilled into; Figure 1b shows a principle diagram of the components of the drilling rig shown in Figure la; Figures 2a to 2d show schematic diagrams of Figure 1b as it performs the steps of a lowering cycle; Figure 3 shows a schematic diagram of a treatment system in which embodiments may operate; Figure 4 shows a plot of hook load against the measured depth for a first example run; Figures 5 to 5d show plots of hook load versus time during one cycle; Figure 6 shows a plot of hook load against the measured depth for a second example run; Figure 7 shows a method for detecting friction according to one embodiment; Figure 8 shows further plots of hook load versus time during one cycle; Figure 9 shows plots of hook load versus time during a cycle where viscous resistance is a factor; and Figure 10 shows a method for detecting viscous resistance according to an embodiment;

Several parts and components of these embodiments are shown in more than one figure; for reasons of clarity, the same reference numbers will be used to refer to the same part and component in all figures.

Detailed description of illustrative embodiments

Figure la shows a principle diagram of a drilling rig system 100 with which embodiments can be used. The embodiment below will be described generally in connection with a casing string that is lowered by a drilling rig into an oil well. However, it is obvious that embodiments are not limited to such situations, and include the situations in which any element, particularly a tubular element, is moved (ie raised or lowered) in a borehole. Such situations will include, but are not limited to, the drilling of both production and injection wells for an oil or gas extraction system, as well as the drilling of boreholes in aquifers and the like.

The system 100 comprises a drilling rig 102 which is configured for drilling

the rock formations beneath it. A casing string, comprising a plurality of joints 104, is shown extended in the rock formations from the rig 102. Rock formations comprise a first layer 106, below which a hydrocarbon-bearing reservoir 108 is located. It should be understood that this diagram is simplified, and that the rock formation can be significantly more complex than

those shown; for example, the upper layer of stone 106 may comprise several discrete layers of different compositions. Likewise, the reservoir 108 may include several hydrocarbon-bearing layers layered with non-hydrocarbon-bearing rock layers. It should also be understood that embodiments are similarly applicable to offshore rigs (even if a seawater layer is not shown in the figure).

Figure 1b shows a more detailed principle diagram of the drilling rig 102 shown in Figure 1a. As in Figure 1a, the links 104 in the casing string are shown extending downwards from the rig into the rock formations below. The rig 102 comprises a tower 110 which provides a frame to support the various elements of the rig, and which extends upwards so that loads (especially the casing string) can be suspended therefrom to be raised and lowered.

At the base of the tower are wedges 112 through which the casing string 104 passes. The wedges 112 can be applied to grip the casing string 104 to prevent its movement and likewise can be released to allow raising or lowering of the casing string 104. It will be obvious that when the term wedges is used herein, any device or means capable of selectively gripping and releasing the casing string is used instead.

Connected to the tower 110 is a suspension system 114 from which a load (in this case the casing string) can be suspended to be raised and/or lowered. In this example, the suspension system 114 comprises: an upper "crown block" 116 which is attached to the tower 110; a lower "running block" 118 which is tied to the crown block 116 by several loops of a hoist cable 120; and a hook 122 which is attached to the runner block 118. The hoist cable 120 extends from the crown block to a winch or "haul" 124.

By reeling in and reeling out the hoist cable from the traction mechanism 124, the running block 118 and the hook 122 can be lowered and raised, where several sheaves in the blocks provide a mechanical advantage. Loads, such as the casing string, can be suspended from the hook 122 so that they are raised and lowered.

The rig 102 is capable of measuring the "hook load"; that is, downward force or load on the hook 122 (or more generally on the suspension system 114). The hook load can be measured by a dedicated device, or can be measured by systems integrated into the suspension system 114 and/or traction mechanism 124. For example, the hook load can be measured by a load meter that measures the load on the hoist cable 120; by a device that measures torque on the drum in the traction mechanism 124, or by a special connection between the running block 118 and the hook 122. Many systems and methods for measuring the hook load are known in the art and can be used in embodiments.

It should be understood that the suspension system 114 described above is only intended as an example, and that any mechanism capable of moving an element, particularly a tubular element such as a casing string, in a borehole may be used. For example, the hook 122 may be replaced by a set of teeth arranged to grip the casing string, and the blocks 116 and 118 may be replaced by a hydraulic or pneumatic system. Some rigs are capable of exerting a downward force on a tubular member to force the tubular member into the borehole. In general, the rig may comprise a movable device (for example, a hook) which is attached to the tubular member (for example, the casing string), and is used to move the tubular member within the borehole (either to raise or lower it).

The operation of the rig 102 described above when driving in (lowering) a casing string will now be described below with reference to Figures 2a to 2d. As briefly mentioned above, this process is carried out over a number of cycles. Each of figures 2a to 2d shows a simplified version of the rig 102 shown in figure 1b at various points in a cycle.

The beginning of a cycle is shown in figure 2a: in this figure, the upper link 104a of the casing string is held in the wedges 112 and the suspension system 114 is raised. As discussed above, "leg" is a well-known term in the art and refers to a section of the casing string.

In the second stage of the cycle, as shown in Figure 2b, a new link 104b is attached to the top of the casing string. Furthermore, the casing string in its entirety, with the new additional link 104b, is attached to the suspension system 114.

When the new joint 104b is attached, the wedges are released so that the casing string is now suspended from the suspension system 114. The suspension system 114 then lowers the hook, and the attached casing string, into the borehole. This is shown in Figure 2c by arrow 202.

Finally, once the new casing string joint 104b is lowered into the wellbore, the wedges 112 are applied to grip the joint 104b. Then, as shown in Figure 2d, the casing string/link 104b is released from the suspension system 114, and the suspension system 114 is raised (as shown by arrow 204) to return to the position shown in Figure 2a, ready for the next link. The cycle is then repeated for the subsequent joints.

While the above has been described with reference to a single link, some towers are tall enough to be able to accommodate multiple links in each cycle. That is, the additional length of casing string attached per cycle comprises 2, 3 or even 4 joints (for example of lengths of 80, 120 and 160 feet respectively, corresponding to approximately 24, 36 and 48 m). It should be understood that such extended lengths may be used in embodiments.

During any given cycle, the hook load is measured by the rig and the hook load is output to a computer system. In this regard, embodiments provide systems, and methods and computer programs that can be used during the movement of an element, particularly a tubular element such as a casing string inside a borehole, to identify forces on the element. To do so, embodiments may include a computer system running friction measurement (FM) software components that enable the system to identify these forces and, if desired, predict a stuck pipe, or other undesirable occurrences, which will be described in more detail below. In one particular embodiment, the system can identify friction between the element and the borehole, and based on this identification, for example, can predict differential jamming. This is described with special reference to figures 4 to 7.1 another embodiment, the system can identify viscous resistance in the borehole, and uses this to identify downhole pressure waves. This is described with special reference to figures 9 and 10.

The computer system may be located in a rig control center (which may be part of the rig or located at a significant distance from the rig, including in another country). Alternatively, the computer system may be part of the control system of the rig, and may, for example, be integrated with the systems that control the traction devices 124. The FM software components may include one or more applications known in the art, and/or may include one or more add-on modules for existing software .

A block diagram illustrating such a computer system will now be described with reference to Figure 3. The computer system 300 comprises a processing unit 302 with a processor, or CPU, 304 which is connected to a volatile memory (ie RAM) 306 and a non-volatile memory (such as a hard disk) 308. The FM software components 310, which provide instructions for implementing embodiments, may be stored in the non-volatile memory 308. Additionally, the CPU 304 may be connected to one or more interfaces such as rig interfaces

312, user interface 314 and a network interface 316.

The rig interface 312 is connected to the rig 102 as described above, and is capable of receiving data indicating the hook load as measured by the rig 102. The rig interface can also receive data indicating, for example, the position of the suspension system 114 (ie, the height of the hook), the mode of operation (applied or released) to the wedge 112, or any other operational data associated with the rig 102 that may be necessary to implement embodiments.

The user interface 314 can provide inputs and outputs for the operator of the rig. The nature of these inputs and outputs and their application to the rig operator will be apparent from the description below. The network interface 316 can be a wired or wireless interface and is connected to a network, represented by cloud 318. The computer system 300 can receive data or software components via the network 318, and can provide an output to other computer systems via the same.

During operation, and according to standard procedures, the processor 304 retrieves and executes FM software components 310 stored in the non-volatile memory 308. During the execution of the FM software components 310 (which is when the computer system performs the actions described below), the processor may store data temporarily in the volatile memory 306. The processor 304 also receives data through rig interface 312 (and/or user interface 314 or network interface 316 as needed to implement embodiments).

As defined by instructions in the FM software components 310, the processor 304 processes the received data. After processing the data, the processor 304 may provide an output via any of the interfaces 312, 314 and 316. Such processes will be readily apparent to those skilled in the art and will therefore not be described in detail.

Embodiments are capable of identifying the forces on the element, particularly a tubular element such as a casing string. These forces can be caused by friction between the element and the borehole, or alternatively by viscous resistance on the element caused by displaced fluid. Furthermore, the embodiments are capable of predicting or predicting future jamming of the element from this identified friction. An example configuration and output of computer system 300 will now be described with reference to Figures 4 through 7. Figures 4 through 6 show the plots of measurements derived from the hook load value received during cycles. Figure 7 shows an example of a method for identifying friction between a casing string and the borehole. The methods described below can all be implemented by the system 300 as embodiments. Also, as discussed above, the methods described below may also be implemented by the system 300 when other tubular elements are moved within a borehole.

By way of background, a plot of hook load versus wellbore depth (ie, length of casing string) will be described with reference to Figure 4. Each point 402 (white circles) in the plot represents a measurement of the hook load at steady state during a given cycle. As mentioned above, the data represented in this plot is usually recorded during the run-in of a casing string into a borehole. It cannot be seen from the plot that the hook load increases as depth increases (indicative of the increasing weight of the extended casing string); however, the increase is not linear due to the changes in dynamic friction caused by the extension of the casing string, as well as the changes in viscous resistance and buoyancy acting on the casing string.

The data shown in Figure 4 represents the prior art method for identifying the steady state hook load value. As mentioned above, these steady state values can be measured "by eye" by an operator as the casing string is lowered. In the plot shown in Figure 4, differential stall occurred after approximately 16,000 ft (4,900 m); however, as can be seen, there is little in the data that would indicate that such differential deadlock was occurring. Consequently, it can be seen that while the steady state hook load can be recorded for the run-in of a casing string, the steady state hook load data cannot be used to identify static friction in the borehole.

As indicated above, embodiments identify static friction in the borehole. For this purpose, the rig 102 and the computer system 300 are arranged such that the rig 102 measures the hook load at a plurality of points during each lowering cycle and transmits data containing a plurality of load values measured thereby to the computer system 300. The data is received by the computer system 300 and analyzed, according to programming instructions encoded in FM software components, such as identifying static friction and predicting differential stalling. A method that can be carried out by the computer system 300 to do this is described with reference to Figure 6 below. To put this method in context, however, Figures 5 and 6, which show plots of hook load data, will be described first. Hook load data shown in Figures 5 and 6 may be analyzed by the computer system 300, however, it is to be understood that the computer system does not have to generate such plots in order to perform our methods of the embodiments, such as that described in connection with Figure 6.

Figures 5a to 5d show four plots of the hook load during a single cycle. These plots are illustrated representations of the hook load value received and

analyzed by the computer system 300 in embodiments. As can be seen from the details of the plots, the hook load is sampled at several points during the respective cycle. In the plots shown, the sampling frequency was once every 5 seconds, to provide approximately 40 hook load values for a given cycle. As discussed below, however, those skilled in the art will appreciate that higher or lower sampling frequencies can be used.

Figure 5 a shows a plot for a first cycle. At the beginning of the cycle (at 00:00 minutes) the hook load is approximately 100 klbs (440 kN). This value represents the weight of those components (such as the hook 122) that are suspended from the hook load measurement device, and are therefore included in the measurements.

At approximately 00:10 minutes, the cycle begins with a relatively sharp increase in hook load from approximately 100 to 450 klbs (440 kN to 2000 kN). This is caused by the wedge 112 being released, and the weight of the casing string being transferred from the wedges 112 to the suspension system 114 (corresponding to the transfer from Figure 2b to Figure 2c). In the plot, the hook load reaches a maximum before decreasing slightly to a value of approximately 425 klbs (1900 kN) at a time period of 00:20 minutes. Such minor oscillations in the hook load can occur (and are typically caused by the elasticity of the system). This sharp increase, and any subsequent oscillations, may be considered to define a first period in which the load (or weight) of the casing string is transferred from the wedge 112 to the suspension system 114.

After this first period, the weight of the casing string is completely suspended from the suspension system 114 and can therefore be lowered into the borehole. This corresponds to the situation shown in Figure 2c. As the casing string is lowered, the hook load oscillates by approximately ±10 klbs (± 44 kN) above and below an average value of approximately 425 klbs (1890 kN). This average value is marked by a white circle 502, whose level of approximately 425 klbs (1890 kN) is indicated by an arrow. The period during which the casing string is suspended from the suspension system 114 and is lowered into the wellbore may be considered a second period (which ends at the beginning of the third period defined below). The arithmetic mean of the hook load can be calculated from samples taken during this period to define the average hook load value; however, other average values, such as frequency classes or median value, can be used.

At the end of the cycle is a third period, in which the wedges are applied and the weight of the casing string is transferred from the suspension system 114 to the wedges 112. This third period is defined by a relatively sharp reduction in the hook load to a level similar to that at the beginning of the cycle. The reduction in hook load marks the start of the third period and consequently the end of the second period.

Figure 5b is similar to Figure 5a, in that the hook load starts at a low value of approximately 100 klbs (440 kN), before increasing sharply during an initial period. During the subsequent second period, the hook load remains approximately constant at a value of approximately 480 klbs (2140 kN), indicated by white circle 504, and then drops in a third period.

However, as can be seen, at the beginning of the second period, there is a drop in the hook load to a level of about 440 klbs (1960 kN), before the hook load increases to the average value of about 480 klbs (2140 kN). This reduction in hook load is generally caused by static friction in the wellbore (which supports some of the weight of the casing string). As time passes, the downward force on the area increases until static friction increases until static friction is overcome. With the reduction in friction associated with overcoming the static friction and thus the transition to dynamic friction, the force on the hook increases, and consequently the hook load value increases to the average value 504. The hook load will generally reach a minimum just before the static friction is overcome. This minimum value is marked by the black circle 506 and will hereafter be referred to as the reduced hook load value.

Figures 5c and 5d show the same effect as Figure 5b, namely a drop in the hook load at the beginning of the second period of the cycle; however, in each case the difference between the mean value and the reduced value is more apparent.

In Figure 5c, the hook load initially increases to a value of approximately 470 klbs (2090 kN), before dropping to a value of approximately 420 klbs (1870 kN). After this point (as the static friction is overcome) the hook load value increases to the average value of approximately 500 klbs (2220 kN). The average value is marked by white circle 508 and the reduced value by black circle 510.

In Figure 5d, the hook load initially increases to a value of approximately 510 klbs (2270 kN), before decreasing to a value of approximately 400 klbs (1780 kN). The hook load value later increases to the average value of approximately 560 klbs (2490 kN). The average value is marked by white circle 512 and the reduced value by black circle 514.

Figure 6 shows a plot, similar to that shown in Figure 4, but with both the white and black circles plotted. Each of the plots shown in figure 5 a to 5 d contributes a white data point in the plot, and if relevant, a black data point. The depths corresponding to each plot are marked by arrows a to d, where each corresponds to Figures 5a to 5d respectively. In addition, a set of points shows the difference between the average value (white points) and the reduced value (black points) as cross 516. This calculated difference can be considered as an indication of the friction in the borehole. A trend line 518, calculated using regression analysis, is shown, representing the trend of the points.

As was evident from Figure 5a, there was no clearly defined reduction in hook load (ie no clearly defined reduced hook load value / black circle). This is relevant for all measurements taken before around 9,500 feet (2,900 m). Therefore, for clarity, the corresponding black circles are not plotted on Figure 6 for measured depths of 9,500 ft (2,900 m) or less (and can be assumed to be approximately the same value as the average hook load values / white circles). After 9,500 ft (2,900 m) depth, however, the reduction in strain value becomes more clearly defined, and therefore the corresponding black circles are plotted on Figure 6. As can be seen, the data points represented by black circles are separated from the data points represented by the white circles. In the plot shown in Figure 6, differential stall occurred at approximately 16,000 ft (4,900 m); however, it appears that the separation of the white and black data points predicts this differential stall from approximately 9,500 feet (2,900 m) depth. This difference can be seen from the increase in the friction value, represented by the crosses). Therefore, in embodiments, the point where the white and black data points diverge can be used to identify the friction in the borehole and consequently to predict differential jamming.

A method by which the computer system 300 derives a measure of the static friction and is therefore able to predict differential stalling will now be described with reference to Figure 7.

In step 702, a cycle begins as described above with reference to Figure 2. During the cycle, the rig 102 transmits rig data to the computer system 300. The data is received through the rig interface 312, and may be sent to the processor 304 for immediate analysis, or may be stored in any of the memories 306 or 308 for analysis later. This data contains a plurality of hook load values received at a plurality of points during the cycle. The hook load values are indexed (such as by a time stamp or a single number in ascending order) so that they can be identified in the order in which they are measured. The received data may, in addition, contain data on the operational status of the wedges, and/or the position of the hook/suspension system, and this data can also be indexed.

In step 704, the processor 304 analyzes the data to identify the second period as described above with reference to Figure 5, where the second period is the period in which the casing string is suspended from the suspension system 114 and lowered into the wellbore. There are a number of methods by which the processor 304 can identify the second period in the received data: one example is to identify sharp increases and decreases in the load values associated with the transfer of the weight of the casing string between the wedges 112 and the suspension system 114. Alternative methods will be discussed below . Upon identifying the second period, the processor 304 identifies the index of the start and end points of the second period.

In step 706, once the second period is identified, processor 304 identifies the hook load values that correspond to the points in time in the second period. In other words, the processor identifies those hook load values that have an index value between the start and end points identified in step 704. The processor 304 then calculates an average value for the identified hook load. The average value can be calculated as mean, median or mode data values for hook load.

In step 708, the processor 304 additionally analyzes the hook load value corresponding to the second period to identify a reduced value. In this example, this reduced value is calculated by the processor to be the minimum of the hook load value corresponding to the second period.

In step 710, the processor 304 calculates a friction value indicative of the friction in the borehole. In this example, this friction value is the difference between the average and the reduced value; however, other methods may be used, such as those involving the calculation of a value indicative of friction per unit length (the difference between the average and the reduced values, divided by the total length of the casing string). Alternatively, the reduced value can be taken directly as the friction value.

In step 712, one or more of the average value, the reduced value, or the friction value is stored in one or both of the memories 306 and 308. Alternatively or additionally, the value may be transmitted to a remote station using the network interface 316, or provided to an operator using user interface 314. The values can be stored with an identifying index, such as the total depth of the wellbore or the length of the casing string so that the trends between several sinking cycles can be determined. Steps 702 through 712 are then repeated for subsequent lowering cycles.

After a number of cycles are analyzed as described in steps 702 through 712, the processor 304 may analyze the recorded data as described below in steps 714 and 716.

One method by which the processor 304 analyzes the data is to identify the trends in the average value, the reduced value, and/or the friction value, as shown in step 714. There are many methods by which this can be done; however, in general, the processor looks for a series of consecutive lowering cycles for which the values are indicative of a consistently high or increasing level of static friction. For example, the processor 304 may calculate a moving average of the friction values for a given number of lowering cycles (such as 20, but any relevant number may be used). In this way, the processor 304 is able to filter out minor variations, errors, and some abnormal lowering cycles that produce a high friction value.

Alternatively, regression analysis or similar techniques can be used to derive a trend for a series of data values. This analysis can also be performed on a rolling basis, using a set of data points. Such a tendency is shown in Figure 6 and was calculated for the friction values from a depth of 10,000 feet to 16,000 feet (approximately 3000 m to 4900 m).

After any trends in the data are determined (in step 714), the processor 304 can, in subsequent step 716, use the calculated trends to predict a stuck pipe condition. For example, the processor 304 may compare the moving average of the friction values to a threshold, and if the processor 304 determines that the moving average is above the threshold, the processor determines that a stuck pipe is likely to occur. Alternative methods can be used, such as extrapolating the tendency calculated in 714 with the target depth of the borehole, and comparing the extrapolated friction value at the target depth to a threshold value. Should the value be above the threshold, this can be considered an indication of a condition that a stuck pipe (caused by high static friction) will occur before the target depth is reached. In some embodiments, the processor may calculate a probability that a stuck pipe condition will occur. For example, the processor 304 may divide the current or predicted friction value by a predetermined number to derive a percentage probability of a stuck pipe condition occurring.

After a prediction of the probability of stuck pipe conditions is identified, the processor may output data through one or more of the interfaces 312, 314, and 316, for example, to alert the rig operator that differential sticking is occurring and that it is likely that it is going to result in a tube that gets stuck.

Therefore, in embodiments, the multiple samples of hook load are analyzed over time (during a cycle) to identify not only the average (or steady state) hook load value, but to detect static friction from changes, during a cycle, in the hook load values. These changes can be used not only to identify static friction, but also to predict the occurrence of a stuck pipe condition.

Additional details and modifications

The procedure described above, particularly with reference to trend 516 in Figure 6, indicates that a large number of cycles will show a difference between the minimum and average hook load values before a stuck pipe condition occurs. This need not be the case and less than five, especially only two or three cycles may show this difference before a stuck pipe condition occurs. Thus, in some embodiments, two, three, or four adjacent cycles in which there is a significant difference between the average and minimum hook load values may be considered an indication that differential setting is occurring. At which point the casing can be partially retracted and sunk again to solve the problem.

The above embodiments are described in the specific context of lowering a casing string into a wellbore; however, other applications are also possible. For example, embodiments are relevant to any situation where a tubular element is moved within a borehole (either raised or lowered). Furthermore, the tubular element can be made of an alternative element of a casing string, such as a casing string, production string, injection string or a drill string.

Furthermore, while the casing string is described as being suspended from the suspension system 114, the rig 102 may alternatively be arranged to force the tubular member down into the borehole. In such cases, the load values may represent the force necessary to force the tubular element down the borehole. Accordingly, any system that provides a movable unit to which the tubular member is attached (to be raised, lowered or forced down) may be used in embodiments.

In the above embodiments, the index for identifying points during individual sinking cycles was time, and the index for identifying different sinking cycles was measured depth (ie, the length of the tubular member in the borehole). However, it should be understood that any relevant index can be used.

The detection of the second period can be done in a number of ways, for example the processor 304 can look for the rapid changes in hook load to define the boundaries of the periods. The system can include a guard interval during this period to ensure that any oscillations in the hook load associated with the transfer of weight do not lead to errors in the results. The guard interval may be a predetermined period of time (ie, a period of a given number of seconds), or may be determined based on analysis of a given number of data samples, for example by checking for oscillations in the data samples.

Alternatively, the processor 304 may be able to receive data on the operational status of the wedges 112 or on the suspension system 114 through the rig interface 312. The processor 304 may use this data to define the second period, for example by looking for wedge opening and closing, or looking at the position or movement of the suspension system 114. For example, the processor 304 may look for conditions in which the hook 122 of the suspension system 114 moves, or in which the hook 122 is between a given set of positions. Other methods of identifying the second period will be apparent to those skilled in the art.

When the reduced value is detected, the processing system 300 may apply a specified minimum value. Alternatively, however, the processing system 300 can remove errors by, for example, calculating an average for a number of the lowest values, or defining the friction value as given by a given percentile of all values (thereby excluding some of the very lowest values).

While the friction value described above was calculated as the difference between the average value and the minimum value in any given second period, the processor may alternatively identify other data to calculate this value. For example, the friction value can be calculated from the variance (or deviation) in the hook load values during a cycle. That is, the processor 304 can look not only for a decrease in the hook load values during a cycle, but for rapid changes (ie, increases or decreases) and oscillations.

Alternatively, the processor 304 may look for relatively sudden changes in the load values that are indicative of static friction being overcome. In such embodiments, the friction value can be calculated as the magnitude of any sudden increase in the hook load values. Certain alternative situations will be described with reference to Figures 8a to 8c.

The plot shown in figure 8a is indicative of a case where the direction of movement of the hook is reversed. In other words, the hook (and casing string) is first lowered (as with the embodiment described above), but between a time period of 2:00 and 2:30 minutes the hook is raised, before being lowered again (after 2:30 minutes). In this case, an average hook load value 802 and a maximum hook load value 804 can be identified from the load values. The difference between these load values can be used to identify friction in the borehole, in particular it can be used to differentiate between buoyancy and friction.

The plot shown in Figure 8b is indicative of the case where there is a large degree of variation in the load values as a result of friction between the borehole and the casing string. In such cases, the degree of variation in the load values can be used as a measure of the degree of friction.

In this further embodiment, the difference between the average and maximum hook load values in Figure 8a and the variation in the load value in Figure 8b can be recorded for a plurality of cycles, and consequently used to determine tendencies and the like (as described above with reference to Figure 6).

Figure 8c shows a plot in case the casing string has stuck. This is represented by the tapered reduction in the hook load values (which should be compared to the abrupt reduction associated with application of the wedges). In this case, an analysis of the hook load values during this cycle, and further a comparison of the hook load values of this cycle with previous cycles, may enable the cause of the stuck pipe condition to be diagnosed. For example, if the previous cycles did not show the indication of increased static friction (as shown in Figures 5a to 5d), then the cause of this stuck pipe condition can be diagnosed to be caused by, for example, a wellbore collapse. This can make it easier to avoid the stuck pipe condition, or provide rig operators with information about the wellbore environment (to facilitate future run-in of a casing string or future drilling operations (ie, expanding the wellbore).

The frequency at which the hook load is sampled can be changed to provide the best use of data. In the examples above, a sampling rate of once every 5 seconds was used, giving approximately 40 data samples per cycle; however, a much higher (ie from once every 0.1 second to 2 seconds, 10Hz to 0.5Hz) sampling rate can be used.

The processor 304 may identify a steady state to identify the average value. The steady state can be defined as a period in which the hook load values are all within a predetermined range relative to each other (or have a variation below a predetermined value) over a predetermined time period, such as from 15 seconds to 2.5 minutes, for example 30 seconds or 1 or 2 minutes.

The above description focuses on determining friction between the borehole and

the casing string, however, this is not the only metric that can be determined from a plurality of hook load values taken during a cycle. Figures 9 and 10 will be used to describe a method for determining a different force on an element that is moved inside a borehole, in this case viscous resistance caused by the movement of the element. Figure 9A shows a plot of hook load in relation to time as a casing pipe is driven down the hole, i.e. lowered into a borehole. As the casing is driven down the hole, fluid is displaced through the annulus, up the borehole towards the surface. The movement of the fluid through the annulus towards the surface causes a viscous resistance force that counteracts the movement of the casing (which is away from the surface). The viscous drag can be observed as a reduction in the hook load as shown in Figure 9A. As illustrated, as the casing is lowered, an increased amount of fluid is displaced, and the thrust therefore increases. This is shown by the progressive reduction in hook load throughout the cycle. With the exception of minor short-term variations, the progressive reduction is monotonic and can be modeled as being approximately linear. In this way, such a linear tendency can be determined for this change in the hook load values. This trend is shown by line 902. The trend continues from a maximum value at the beginning of the cycle, indicated by arrow 904, to a minimum value at the end of the cycle, shown by arrow 906. Figure 9B shows a similar case where the casing is brought up, that is lifted out of the borehole. As the casing is raised, the drawn fluid along the annulus is raised from the surface. The viscous drag force again counteracts the movement of the casing string, and is therefore observed as an increase in surface hook load as shown in Figure 9B. Similarly to Figure 9A, Figure 9B shows how the hook load progressively increases, as indicated by trend line 908. The trend proceeds from an initial minimum value at the beginning of the cycle, as shown by arrow 906, to a maximum value at the end of the cycle as shown by arrow 908 .

The fluid flow caused by the movement of the casing string in the borehole can generate significant downhole pressure waves. In cases where the string is lowered, a downhole shock wave pressure can be created. The pressure from this wave must not exceed the open hole formation's fracture pressure, otherwise fluid loss may occur and fractures may form in the formation. Correspondingly, when the casing string is raised, a downhole mud pressure wave (eng.: swab pressure wave) can be created. The pressure caused by this wave must not fall below the open hole formation pore pressure, otherwise an influx of fluid into the borehole may occur, potentially leading to a well control event.

The magnitude and rate of changes in the viscous drag can depend on a number of design factors. These include the size of the pipe, annular clearance, the rate of casing insertion or withdrawal, the length of casing being moved, and fluid properties. The measurements of the viscous resistance can nevertheless be used to provide a method for determining the severity of mud and shock wave pressure, which cannot currently be measured downhole during operations such as running in casing, casing and completion.

To measure the viscous resistance forces, the magnitude of the force can be determined based on the magnitude of the monotonic change in the values. This can be done by comparing the maximum and minimum values, as illustrated in Figures 9A and 9B. In some embodiments, these maximum and minimum values can be determined, for example, by averaging a predetermined number of values at the beginning and end of the cycle, and differentiating the two averages. Alternatively, a linear trend can be determined for the monotonic change, and the value of the trend at the beginning and end of the cycle can be used as the maximum and minimum values. It will be understood that any outliers, such as sudden peaks caused by differential settling as described above, are to be excluded in the determination of these maximum and minimum values. Alternatively, the gradient of the tendency, i.e. the rate of change in the hook load, can be used as a measure of the viscous resistance. The measurements of viscous resistance for a plurality of cycles, like the method above, can be used to predict downhole events.

A method by which the computer system 300 derives a measure of the viscous resistance and is therefore able to predict downhole pressure waves will now be described with reference to Figure 10.

Steps 1002 and 1004 are analogous to steps 702 and 704 above and will therefore not be described in detail. In these steps, the processor 304 receives the hook load values and identifies the second period in these hook load values.

The processor then identifies a magnitude of the monotonic change in the hook load values. One method by which this can be done is illustrated in steps 1006 and 1008.

In step 1006, after the second period is identified, the processor 304 trends the hook load values during the second period. In other words, the processor identifies those hook load values that have an index value between the start and end points identified in step 704. The processor 304 then calculates a trend for the values. The trend can be calculated, for example, by applying linear regression or other techniques. When calculating the tendency, the processor 304 can omit any deviating values. For example, if a small amount of differential fixation occurs, there may be a low value at the beginning of the cycle, as shown in Figure 5b, which can be omitted so as not to distort the results.

In step 1008, the processor 304 may additionally determine the gradient of the tendency as a measure of the viscous resistance. Alternatively or additionally, the processor may determine in step 1010 a maximum and a minimum value for the tendency over the cycle. These values may correspond to the maximum and minimum values of the hook load over the cycle, in order to omit any outliers (caused by e.g. differential fixing), however, the tendency can be used to determine the maximum and minimum. Thus, the value of the trend line at the beginning and end of the cycle can be used to determine the maximum and minimum value as needed. The difference between the maximum and minimum values can be used as a measure of viscous resistance.

In step 1012, one or more values calculated above as a measure of the viscous resistance (collectively called viscous traction values) are stored in one or both memories 306 and 308. Alternatively or additionally, the value may be transmitted to a remote station using the network interface 316, or provided to an operator using user interface 314. The values may be stored with an identifying index, such as the total depth of the wellbore or the length of the casing string so that trends between several sinking cycles can be determined. Steps 1002 through 1012 are then repeated for the subsequent lowering cycles.

After one or more of the cycles are analyzed as described in steps 1002 through 1012, the processor 304 may analyze the recorded data as described below in steps 1014 and 1016.

One method by which the processor 304 analyzes the data is to identify trends in the viscous resistance values, as shown in step 1014. There are many methods by which this can be done; however, in general, the processor looks for a series of successive lowering cycles for which the values are indicative of a consistently high or increasing level of viscous resistance. For example, the processor 304 may calculate a moving average of the viscous resistance values for a given number of dip cycles (such as 20, but any relevant number may be used). In this way, the processor 304 is able to filter out minor variations, errors, and some abnormal lowering cycles that produce a high value for viscous resistance. Alternatively, regression analysis or similar techniques can be used to derive a trend for a series of data values. This analysis can also be performed on a rolling basis, using a set of data points.

In step 1016, the processor 304 may use the values of viscous resistance for one or more of the cycles, or use the calculated tendencies, to predict downhole pressure waves. This can be done by using the determined values as an input to a model of the downhole conditions. The prediction can then, for example, be used to adjust the speed used when the casing is moved into or out of the borehole.

The viscous resistance can be very significant in wells with casing designs with tight tolerances, i.e. casing with a large diameter that is driven into existing casing with a narrow annulus. This is typical for well designs in deep water and HPHT (high pressure, high temperature) environments. The viscous resistance may be negligible for operations involving large annulus, e.g. when driving in or withdrawing drill pipe in holes with a large diameter.

However, by determining a viscous resistance value, from a plurality of hook load measurements taken over a cycle, the above method can be used to influence operating parameters during casing, casing and completion operations.

It should be understood that the details of the above description are intended as examples, and that the person skilled in the art, with the help of data obtained from a variety of rigs from a variety of operations in which tubular elements are moved within a borehole, will be able to process the criteria to identify static friction, and further be able to accurately assess the risk of a stuck pipe condition occurring. Such treatments will be within the realm of trial and error, and therefore fall within the scope of the invention.

It should be understood that any feature described in connection with any embodiment may be used alone, or in conjunction with other features described, and may also be used in conjunction with one or more features of any of the other embodiments , or any combination of any of the other embodiments. Furthermore, equivalents and modifications that are not described above can also be used without deviating from the scope of the invention, which is defined in the accompanying claims. The features according to the requirements can be combined in other combinations than those specified in the requirements.

Claims (69)

1. System for identifying a force on an element being moved within a borehole, by a rig, the rig comprising a movable unit to which the element is attached to be moved within the borehole, and wedges to hold the element, wherein the element is moved in a plurality of cycles, each cycle comprising, in sequence, holding the element in the wedges, releasing the wedges so that the element is moved within the borehole, and applying the wedges so that the element is again held by the wedges, and the rig comprises a measurement unit arranged to measure a force transmitted by the element on the movable unit, and is arranged to output first data indicative of a plurality of load values, where each data element of the first data is indicative of a force measured at each of a plurality of points during a cycle, wherein the system comprises: an interface arranged to receive data from the measurement unit; and a data processing system arranged for each of a plurality of the cycles to: identify a plurality of the load values from the received data, each load value corresponding to a different time with respect to the cycle, and determine other data indicative of a force on the element from the identified the plurality of load values. 2. The system of claim 1, wherein the data processing system is arranged to identify a monotonic change in the plurality of values over the cycle, and to determine a magnitude of the monotonic change to determine the other data. 3. The system according to claim 1 or claim 2, wherein the data processing system is arranged to identify a linear tendency in the plurality of values, and to determine a difference between a value of the tendency at the beginning of the cycle and a value of the tendency at the end of the cycle to determine the other data. 4. The system according to any one of claims 1 to 3, wherein the data processing system is arranged to identify a linear trend in the plurality of values and to determine a gradient of the trend to determine the other data. 5. The system of any preceding claim, wherein the other data is indicative of a viscous resisting force on the member as it is moved within the borehole. 6. The system of any preceding claim, wherein the data processing system is arranged to: determine the other data for a plurality of the cycles; and determining, by applying the other data, whether a force on the element is increasing. 7. The system according to any one of the preceding claims, wherein the data processing system is arranged to determine a trend in the other data to determine whether a force on the element is increasing. 8. The system according to claim 1 or any of claims 6 or 7 depends on claim 1, wherein the force is friction between the borehole and the member. 9. The system of claim 8, wherein the data processing system is arranged to determine a variation of the plurality of load values to determine the other data. 10. The system of claim 8, wherein the data processing system is arranged to compare the plurality of load values with a predicted load value to determine the other data. 11. The system of claim 8, wherein the data processing system is arranged to identify an average value from the plurality of load values and a minimum value from the plurality of load values, and to compare the average value and the minimum value to determine the other data. 12. The system of claim 11, wherein the data processing system is arranged to calculate at least one of a mean value, a weighted mean value, a frequency class, a median value, or a steady state value to determine the mean value. 13. The system according to any one of the preceding claims, wherein the data processing system is arranged to calculate a risk value indicative of the probability of the element driving into the borehole from the other data. 14. The system of any preceding claim wherein the data processing system is arranged to: identify a period of time in the load cycle, which period is between the wedges being released and applied; and identifying a set of the load values corresponding to times during the identified time period to identify the plurality of the load values. 15. The system of claim 14, wherein the data processing system is arranged to detect a change in the load values between a level indicative of the element held in the wedges, and a level indicative of the element supported by the movable unit, to identify the time period. 16. The system according to claim 15, wherein the data processing system is arranged to compare the load values with a threshold value to detect the change. 17. The system of claim 15 or claim 16, wherein the data processing system is arranged to identify the time period to begin a predetermined duration after a detected change. 18. The system according to any one of claims 15 to 17, wherein the data processing system is arranged to identify the time period to begin a predetermined duration before a detected change. 19. The system of any one of claims 14 to 18, wherein the data processing system is arranged to detect at least one oscillation in the load values associated with the wedges being released or applied to identify the time period. 20. The system according to any one of claims 14 to 19, wherein the interface is arranged to receive positional data indicative of the position of the movable unit at the times; and wherein the data processing system is arranged to determine the position of the movable device by using the position data to identify the time period. 21. The system of claim 20, wherein the data processing system is arranged to determine whether the movable unit is between a first or second position to identify the time period. 22. The system of claim 20 or 21, wherein the data processing system is arranged to determine whether the movable unit is in motion to identify the time period. 23. The system of any preceding claim, wherein the interface is arranged to receive operation mode data indicative of whether the wedges are applied or released, and wherein the data processing system is arranged to use the operation mode data to identify the time period. 24. Method of identifying a force on an element being moved within a borehole, by a rig, wherein the rig comprises a movable unit to which the element is attached to be moved within the borehole, and wedges to hold the element, wherein the element is moved in a plurality of cycles, each cycle comprising holding the element in the wedges, releasing the wedges so that the element is moved within the borehole, and applying the wedges so that the element is again held by the wedges, and the rig comprises a measurement unit arranged to measure a force transmitted by the element on the movable unit, and is arranged to output first data indicative of a plurality of load values, where each data element of the first data is indicative of the force measured at each of a plurality points during a cycle, wherein the method comprises: receiving data from the measurement unit; and for each of a plurality of the cycles: identifying a plurality of the load values from the received data, each load value corresponding to a different time with respect to the cycle, and determining other data indicative of a force on the element from the identified plurality of load values. 25. The method of claim 24, comprising identifying a monotonic change in the plurality of values over the cycle, and determining a magnitude of the monotonic change to determine the other data. 26. The method according to claim 24 or claim 25, comprising identifying a linear tendency in the plurality of values, and determining a difference between a value of the tendency at a beginning of the cycle and a value of the tendency at an end of the cycle to determine the other data. 27. The method of any one of claims 24 to 26, comprising identifying a linear trend in the plurality of values, and determining a gradient of the trend to determine the other data. 28. The method of any one of claims 24 to 27, wherein the other data is indicative of a viscous resistive force on the member as it is moved within the borehole. 29. The method of any one of claims 24 to 28, comprising: determining the second data for a plurality of the cycles; and determining, by applying the other data, whether a force on the element is increasing. 30. The method of any one of claims 24 to 29, comprising determining a trend in the other data to determine whether a force on the element is increasing. 31. The method of claim 24 or any one of claims 29 or 30, wherein the force is friction between the borehole and the member. 32. The method of claim 31, comprising determining a variation of the plurality of load values to determine the other data. 33. Method according to claim 31, comprising comparing the plurality of load values with a predicted load value to determine the other data. 34. The method of claim 31, comprising identifying an average value from the plurality of load values and a minimum value from the plurality of load values, and comparing the average value and the minimum value to determine the other data. 35. The method of claim 34, comprising calculating at least one of a mean value, a weighted mean value, a frequency class, a median value, or a steady state value to determine the mean value. 36. The method according to any one of claims 31 to 35, comprising calculating a risk value indicative of the probability of the element becoming stuck in the borehole, from the other data. 37. The method of any one of claims 31 to 36, comprising: identifying a time period in the loading cycle, the period being between the wedges being released and the wedges being applied; and identifying a set of the load values corresponding to times during the identified time period to identify the plurality of the load values. 38. The method of claim 37, comprising detecting a change in the load values between a level indicative of the element held in the wedges, and a level indicative of the element supported by the movable unit, to identify the time period. 39. The method according to claim 38, comprising comparing the load values with a threshold value to detect the change. 40. The method of claim 38 or claim 39, comprising identifying the time period to begin a predetermined duration after a detected change. 41. The method according to any one of claims 38 to 40, comprising identifying the time period to end a predetermined duration before a detected change. 42. The method of any one of claims 37 to 41, comprising detecting at least one oscillation in the load values associated with the wedges being released or applied to identify the time period. 43. The method according to any one of claims 37 to 42, comprising receiving position data indicative of the position of the mobile device at the times; and determining the position of the movable device by using the position data to identify the time period. 44. The method of claim 43, comprising determining whether the movable unit is between a first and second position to identify the time period. 45. The method of claim 43 or claim 44, comprising determining whether the movable unit is in motion to identify the time period. 46. The method of any one of claims 31 to 45, comprising receiving operation mode data indicative of whether the wedges are applied or released, using the operation mode data to identify the time period. 47. Computer-readable storage medium storing readable instructions thereon for execution on a computer system for implementing a method of identifying a force on an element being moved within a borehole by a rig, the rig comprising a movable device to which the element is attached to be moved inside the drill hole, and the wedges to hold the element, wherein the element is moved in a plurality of cycles, each cycle comprising holding the element in the wedges, releasing the wedges so that the element is moved within the borehole, and applying the wedges so that the element is again held by the wedges, and the rig comprises a measurement unit arranged to measure a force transmitted by the element on the movable unit, and is arranged to output first data indicative of a plurality of load values, where each data element of the first data is indicative of the force measured at each of a plurality points during a cycle, wherein the method comprises: receiving data from the measurement unit; and for each of a plurality of the cycles: identifying a plurality of the load values from the received data, each load value corresponding to a different time with respect to the cycle, and determining other data indicative of a force on the element from the identified plurality of load values. 48. The computer-readable storage medium of claim 47, wherein the method comprises identifying a monotonic change in the plurality of values over the cycle, and determining a magnitude of the monotonic change to determine the other data. 49. A computer-readable storage medium according to claim 47 or claim 48, wherein the method comprises identifying a linear tendency in the plurality of values, and determining a difference between a value of the tendency at a beginning of the cycle and a value of the tendency at an end of the cycle to determine the other data. 50. The computer-readable storage medium of any one of claims 47 to 49, wherein the method comprises identifying a linear trend in the plurality of values, and determining a gradient of the trend to determine the other data. 51. A computer readable storage medium according to any one of claims 47 to 50, wherein the other data is indicative of a viscous resisting force on the element as it is moved within the borehole. 52. The computer readable medium of any one of claims 47 to 51, wherein the method comprises: determining the second data for a plurality of the cycles; and determining, by applying the other data, whether a force on the element is increasing. 53. The computer-readable storage medium of any one of claims 47 to 52, wherein the method comprises determining a trend in the other data to determine whether a force on the element is increasing. 54. The computer readable storage medium of claim 47 or any one of claims 52 or 53 when depending on claim 47, in which the force is friction between the borehole and the element. 55. The computer-readable storage medium of claim 54, wherein the method comprises determining a variation of the plurality of load values to determine the other data. 56. The computer-readable storage medium of claim 54, wherein the method comprises comparing the plurality of load values with a predicted load value to determine the other data. 57. The computer-readable storage medium of claim 54, wherein the method comprises identifying an average value from the plurality of load values and a minimum value from the plurality of load values, and comparing the average value and the minimum value to determine the other data. 58. The computer readable storage medium of claim 57, wherein the method comprises calculating at least one of a mean value, a weighted mean value, a frequency class, a median value, or a steady state value to determine the mean value. 59. The computer-readable storage medium according to any one of claims 54 to 58, wherein the method comprises calculating a risk value indicative of the probability of the element becoming stuck in the borehole, from the other data. 60. The computer readable medium of any one of claims 54 to 59, wherein the method comprises: identifying a time period in the loading cycle, the period being between the wedges being released and the wedges being applied; and identifying a set of the load values corresponding to times during the identified time period to identify the plurality of the load values. 61. The computer-readable storage medium of claim 60, wherein the method comprises detecting a change in the load values between a level indicative of the element held in the wedges, and a level indicative of the element supported by the removable unit, to identify the time period. 62. The computer-readable storage medium according to claim 61, wherein the method comprises comparing the load values with a threshold value to detect the change. 63. The computer-readable storage medium of claim 61 or claim 62, wherein the method comprises identifying the time period to begin a predetermined duration after a detected change. 64. The computer-readable storage medium of any one of claims 61 to 63, wherein the method comprises identifying the time period to end a predetermined duration before a detected change. 65. The computer-readable storage medium of any one of claims 60 to 64, wherein the method comprises detecting at least one oscillation in the load values associated with the wedges being released or applied to identify the time period. 66. The computer readable storage medium according to any one of claims 60 to 65, wherein the method comprises receiving position data indicative of a position of the movable device at the times; and determining the location of the movable device by using location data to identify the time period. 67. The computer readable storage system of claim 66, wherein the method comprises determining whether the removable device is between a first or second position to identify the time period. 68. The computer-readable storage medium of claim 66 or claim 67, wherein the method comprises determining whether the removable device is in motion to identify the time period. 69. The computer-readable storage medium of any one of claims 54 to 68, wherein the method comprises receiving operation mode data indicative of whether the wedges are engaged or disengaged, using the operation mode data to identify the time period.